This invention relates to communications in electric and other utilities; and, more particularly, to a method and improvements for enhanced communications between disparate installations in a utility's distribution system under a wide variety of operational conditions.
A utility supplies a particular commodity (electricity, gas, water) through a distribution system to numerous end users. Each utility has a dedicated supply network or grid by which the commodity is routed from a central site or sites to the location of the respective end users. It is now commonplace for a measuring device or meter such as a “smart meter” to be installed at each using facility's location, the meter measuring the amount of the commodity dispensed to and/or used at that particular site. Over time communication systems have been developed which enable a central location of the utility to link with and access the user location through the meter to, for example, obtain current commodity usage rates, control use rates of the commodity under certain conditions, etc. Examples of such communication systems include a two-way automatic communications system for a power line carrier or power line communications system (i.e. Aclara Technologies, TWACS®), as well as a radio frequency (RF) system and landline communications systems.
Referring to FIG. 1, a utility U, for example an electric utility, generates electricity which is propagated through power lines L from a central location such as a sub-station S to numerous end user sites such as residential, commercial, or manufacturing establishments or facilities F. It will be understood that while many sites F rely solely on the electricity transmitted over the power lines to operate machinery, systems, and appliances at the facility, some facilities such as facilities F1 and F2 may use local, alternate power sources in addition to the power supplied by the utility. So, for example, facility F1 employs solar panels SP as a primary or secondary source of power; while facility F2 has its own generator G used for this purpose. Regardless, each facility connected to the utility has a meter such as a smart meter M installed at the facility to measure the amount of usage of the commodity (i.e., electricity) supplied to the facility. A communications link C enables correspondence between the utility and each facility connected in the utility's power grid.
Sometimes disruptions occur which prevent the commodity provided by a utility from reaching some or all of the using sites. For example, in an electrical grid, a power line may be downed during a storm or a transformer may be struck by lightning resulting in a power outage. In such instances, querying by the utility's communications system helps identify the location of the outage as well as its extent, so service can be quickly restored.
One problem with today's utility systems is their vulnerability to natural and manmade catastrophes. Computer hackers, for example, have tried to, and in some instances succeeded, in disrupting a utility's operations. Also, there is the increasing threat of terrorists damaging vital portions of the utility's infrastructure incapacitating the utility. It has been known for years that high energy electrical impulses produced by a nuclear explosion can destroy integrated circuit chips which are the heart of the electronics now universally employed throughout homes and industries, including utility systems, causing massive power disruptions.
With respect to natural causes, there is, for example, the susceptibility to solar flares such as those responsible for the so-called Carrington Event of 1859. In that instance, a geomagnetic storm was produced by an intense solar flare. The resulting coronal mass ejection from the sun reached the earth in less than 18 hours and among other things resulted in the failure of telegraph systems throughout North America and Europe. A similar geomagnetic storm in March, 1989 disrupted power across large sections of the Quebec province in Canada. Another “Carrington-class” storm occurred in July, 2012, but missed the earth's orbit. Significantly, in 2013, a joint venture including both insurance companies and scientific groups estimated that the current cost of a Carrington event affecting the U.S. could exceed over $1 trillion in damages. (See www.wikipedia.org under the heading “Solar storm of 1859”).
There is, accordingly, a need to provide operational safeguards to utilities to protect from, or ameliorate, the effects from the possible occurrence of these events.
In addition to the above, utilities currently employ versions of open communications interconnection (OSI) protocols for communications throughout their communications system to obtain operational data, control operations at particular sites, and confirm that the requested operations are performed. An OSI is characterized by its ability to provide communication functions without regard to a utility's underlying internal structure and the technology employed in the system. As understood by those skilled in the art, an OSI classifies the communications process into a series of interconnected layers defined as follows:
Layer 1—physical layer;
Layer 2—data link layer;
Layer 3—network layer;
Layer 4—transport layer;
Layer 5—session layer;
Layer 6—presentation layer; and,
Layer 7—application layer.
A brief overview of an OSI and each of these layers is found at www.wikipedia.org under the heading “OSI model”. A more detailed description of each layer, its functions and operations is found in, for example, Computer Networks, 5th ed., by Tanenbaum and Withal.
Those skilled in the art understand that, at each layer, two entities exchange information/data using an established protocol for that layer. The particular characteristics for each layer and the protocols employed thereat are available in the above references, as well as elsewhere, and are not described herein. It is understood, however, that current protocols available to systems' users are adaptable to a particular system application.
As one example, an International Electrotechnical Commission standard; i.e., IEC 61968-0:2013 is used in utility RF communication systems, at the applications layer, to communicate between a central utility location C, as indicated in FIG. 1, and meters M installed at using sites or facilities F. The IEC 61968-0:2013 standard has different schema (i.e., 48 schema) defined for respective purposes of a communication. One such schema is, for example, to request a meter reading at a site F, and to report the meter reading back to the central location.
A problem with the present schema is that even though some of them are quite large, they are still not necessarily adequate to meet a utility's need for certain applications. Also, the current schema is somewhat cumbersome. For example, a “read meter” request in the IEC 61968-0:2013 format is formulated as a string, and an extensive technique (not described) is required to build an identifier which describes the unit of measure for an electric meter M's measurement. The format uses both whole numbers (integers) and dots (“.”).
Thus, to request a typical dial reading off the face of a residential electricity meter M, the identifier used in an Application Programming Interface (API) would be, for example,                0.0.0.1.4.1.12.0.0.0.0.0.0.0.0.3.72.0,the construction rules specifying 18 fields composed of characters; i.e., the digits and the dots.        